U.S. patent application number 16/046419 was filed with the patent office on 2019-03-28 for poromechanical impact on yield behavior in unconventional reservoirs.
The applicant listed for this patent is CONOCOPHILLIPS COMPANY. Invention is credited to Samarth AGRAWAL, Richard A. ALBERT.
Application Number | 20190093477 16/046419 |
Document ID | / |
Family ID | 65040999 |
Filed Date | 2019-03-28 |
![](/patent/app/20190093477/US20190093477A1-20190328-D00001.png)
![](/patent/app/20190093477/US20190093477A1-20190328-D00002.png)
![](/patent/app/20190093477/US20190093477A1-20190328-D00003.png)
![](/patent/app/20190093477/US20190093477A1-20190328-D00004.png)
![](/patent/app/20190093477/US20190093477A1-20190328-D00005.png)
![](/patent/app/20190093477/US20190093477A1-20190328-D00006.png)
![](/patent/app/20190093477/US20190093477A1-20190328-D00007.png)
![](/patent/app/20190093477/US20190093477A1-20190328-D00008.png)
![](/patent/app/20190093477/US20190093477A1-20190328-M00001.png)
United States Patent
Application |
20190093477 |
Kind Code |
A1 |
AGRAWAL; Samarth ; et
al. |
March 28, 2019 |
POROMECHANICAL IMPACT ON YIELD BEHAVIOR IN UNCONVENTIONAL
RESERVOIRS
Abstract
A method for obtaining hydrocarbon from a reservoir in a
subterranean formation is described. The method includes measuring
a poromechanic pressure change due to lithostatic load sharing in
the subterranean formation. Mapping the poromechanic pressure
change to one or more locations in the subterranean formation.
Identifying one or more local pressure peaks in the poromechanic
pressure change, wherein the one or more local pressure peaks are
each marked by a pressure escalation and subsequent pressure
depletion. Determining one or more regions in the reservoir
exhibiting single phase hydrocarbon production.
Inventors: |
AGRAWAL; Samarth; (Houston,
TX) ; ALBERT; Richard A.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
CONOCOPHILLIPS COMPANY |
Houston |
TX |
US |
|
|
Family ID: |
65040999 |
Appl. No.: |
16/046419 |
Filed: |
July 26, 2018 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
62537118 |
Jul 26, 2017 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01V 2210/646 20130101;
E21B 47/06 20130101; G01V 99/005 20130101; E21B 43/267 20130101;
E21B 43/26 20130101; G01V 1/306 20130101; E21B 49/00 20130101 |
International
Class: |
E21B 49/00 20060101
E21B049/00; G01V 99/00 20060101 G01V099/00; E21B 47/06 20060101
E21B047/06; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method of obtaining hydrocarbon from a reservoir in a
subterranean formation, the method comprising: a) measuring a
poromechanic pressure change due to lithostatic load sharing in the
subterranean formation; b) mapping the poromechanic pressure change
to one or more locations in the subterranean formation; c)
identifying one or more local pressure peaks in the poromechanic
pressure change, wherein the one or more local pressure peaks are
each marked by a pressure escalation and subsequent pressure
depletion; and d) determining one or more regions in the reservoir
exhibiting single phase hydrocarbon production.
2. The method of claim 1, wherein the one or more regions of d)
experience a delay in hydrocarbon phase change due to the pressure
escalation.
3. The method of claim 1, wherein the poromechanic pressure
increase is at least partly due to the Noordbergum effect.
4. The method of claim 1, further comprising: e) extending duration
of the single phase hydrocarbon production by increasing the rate
of drainage in at least a portion of the reservoir.
5. The method of claim 1, further comprising: estimating the
duration of the single phase production.
6. The method of claim 1, wherein a pressure escalation in a
production period is at least partly due to compression in an
undrained part of the hydrocarbon reservoir.
7. The method of claim 4, wherein the increasing rate of drainage
is performed by adjusting one or more producing well parameters
selected from the group consisting of: choke setting, number of
induced fractures, number of fracture clusters, choice of
stimulation fluid, and choice of proppant type.
8. The method of claim 1, wherein an offset production experiences
extended duration of stable surface condensate-gas ratio due to
load-sharing pressure support.
9. The method of claim 1, further comprising: generating
geomechanics simulation model-based type-curves to estimate the
pressure escalation and duration for given reservoir properties and
pressure depletion; and estimating rock layer stiffness and
permeability based on a known pressure escalation and duration,
using the geomechanics simulation models.
10. The method of claim 1, wherein the one or more regions in the
reservoir includes an offset well.
11. The method of claim 1, further comprising: mapping a pressure
escalation in an inter-frac region of the reservoir due to severe
near-fracture drainage.
12. The method of claim 1, further comprising: recovering
hydrocarbons from a refrac well wherein a new fracture experiences
the pressure escalation in the inter-frac region.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional application which
claims benefit under 35 USC .sctn. 119(e) to U.S. Provisional
Application Ser. No. 62/537,118 filed Jul. 26, 2017, entitled
"POROMECHANICAL IMPACT ON YIELD BEHAVIOR IN UNCONVENTIONAL
RESERVOIR," which is incorporated herein in its entirety.
FIELD OF THE INVENTION
[0002] The present invention relates generally to recovery of
hydrocarbons from an unconventional reservoir. More particularly,
but not by way of limitation, embodiments of the present invention
include tools and methods for mapping poromechanic pressure changes
in a subterranean formation which can be used to optimize a
production strategy.
BACKGROUND OF THE INVENTION
[0003] Unconventional reservoirs (UR) typically require massive
stimulation or special recovery processes in order to produce oil
and gas at economically viable flow rates. Compared to conventional
reservoirs, unconventional reservoirs are large in volume and
difficult to develop. Examples of unconventional reservoirs
include, but are not limited to, low permeability oil, tight gas
sands, gas shales, heavy oil, coalbed methane, gas hydrates, and
oil shales.
BRIEF SUMMARY OF THE DISCLOSURE
[0004] The present invention relates generally to recovery of
hydrocarbons from an unconventional reservoir. More particularly,
but not by way of limitation, embodiments of the present invention
include tools and methods for mapping poromechanic pressure changes
in a subterranean formation which can be used to optimize a
production strategy.
[0005] One method of obtaining hydrocarbon from a reservoir in a
subterranean formation includes measuring a poromechanic pressure
change due to lithostatic load sharing in the subterranean
formation; mapping the poromechanic pressure change to one or more
locations in the subterranean formation; identifying one or more
local pressure peaks in the poromechanic pressure change, wherein
the one or more local pressure peaks are each marked by a pressure
escalation and subsequent pressure depletion; and determining one
or more regions in the reservoir exhibiting single phase
hydrocarbon production.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] A more complete understanding of the present invention and
benefits thereof may be acquired by referring to the following
description taken in conjunction with the accompanying drawings in
which:
[0007] FIG. 1 illustrates pressure escalation and pressure
depletion according to one or more embodiments of the present
invention.
[0008] FIG. 2 illustrates pressure escalation and pressure
depletion according to one or more embodiments of the present
invention.
[0009] FIG. 3A illustrates a schematic showing a configuration of a
production well (Producer) and multiple pressure gauges (Gauges X,
Y, Z) according to one or more embodiments of the present
invention.
[0010] FIG. 3B summarizes pressure changes measured at the pressure
gauges.
[0011] FIG. 4 illustrates a simulated graph as described in the
Example.
[0012] FIG. 5 illustrates a simulated graph as described in the
Example.
[0013] FIG. 6A illustrates a simulated graph as described in the
Example.
[0014] FIG. 6B illustrates a simulated graph as described in the
Example.
DETAILED DESCRIPTION
[0015] Reference will now be made in detail to embodiments of the
invention, one or more examples of which are illustrated in the
accompanying drawings. Each example is provided by way of
explanation of the invention, not as a limitation of the invention.
It will be apparent to those skilled in the art that various
modifications and variations can be made in the present invention
without departing from the scope or spirit of the invention. For
instance, features illustrated or described as part of one
embodiment can be used on another embodiment to yield a still
further embodiment. Thus, it is intended that the present invention
cover such modifications and variations that come within the scope
of the invention.
[0016] Pressure depletion in a draining well can provide challenges
to recovering hydrocarbons. Liquid dropout from the gas phase when
reservoir pressure falls below saturation pressure should impair
well productivity due to relative permeability effects. When
pressure drops below the dew point, condensate forms a bank of
fluid in the reservoir that can hamper deliverability. One would
expect that when a reservoir is being drained, pore pressure will
only go down from its initial value. However, this is not always
true for all parts of a reservoir.
[0017] Some unconventional reservoir wells have reported delayed
onset of multiphase effects as measured using changes in condensate
gas ratio (CGR) in the surface-produced flow stream. This delay in
CGR change can be attributed to pressure escalation/support due to
the so-called Mandel-Cryer effect. Previously, Mandel and Cryer
independently observed similar anomalous pressure escalation
responses during a fluid drainage event. This pressure escalation
may be analogous to reverse water fluctuations known as the
Noordbergum effect, first observed by Dutch scientists. As one part
of a water reservoir was drained, other parts experienced a
pressure escalation observable as change in water levels due to
overburden load sharing.
[0018] However, this pressure escalation was largely ignored in
conventional highly permeable reservoirs since the effect was short
lived and low in magnitude. However, this effect becomes greater
when rocks have low permeability (nano Darcy to micro Darcy) as
found in many unconventional reservoirs. This effect may be
particularly accentuated when the rock is characterized by a low
Young's modulus (less than about 2.5 MM psi), low Possion ratio
(about 0.15 to 0.2), and low permeability (less than about 200
nD).
[0019] There are many potential commercial applications of the
present invention. Being able to predict the expected delay in
multiphase CGR onset can help asset engineers make more reliable
reserves forecasts. For example, if the condensate yield starts
declining after 2 years rather than 5 years, the net present value
(NPV) of the well will be vastly different, when considering the
price differential between gas and liquids. An engineer can also
utilize this knowledge to design an optimal drawdown/choke
operating strategy for unconventional reservoir wells in condensate
areas where this phenomenon is anticipated. For
exploration/appraisal leases, application of these concepts can
help high-grade areas where this phenomena can be leveraged with
given mechanical and flow properties of the reservoir rock.
Moreover, the pressure signals depend on production-induced effects
and are therefore a long term signal. This eliminates the risk of
missing essential information such as in methods utilizing
stimulation period data.
[0020] The invention provides systems and methods for utilizing
coupled fluid flow and poromechanical physics to understand why the
CGR of a produced fluid may show delayed multiphase onset in
certain reservoirs but not others. In the past, advanced coupled
flow and geomechanics physical concepts have often been deemed
inapplicable in oil and gas reservoir modeling. While this is
somewhat true in conventional reservoirs (high permeability),
unconventional reservoirs can exhibit far different behavior,
particularly when marked by ultra low permeability and low Young's
modulus.
[0021] As described herein, the term "poromechanical" and its
related terms refer to the branch of physics that deals with
behavior of a fluid-saturated porous medium. The porous medium
refers to a framework of solid material with some internal, voided
pore space, connected or otherwise, that may contain fluid in
liquid or gaseous form. Both the solid and the void space fluids
have unique physical properties which often leads to
counter-intuitive physical phenomena when exposed to external
forces as a system rather than only solid or fluid.
[0022] The present invention can help estimate the magnitude of a
pressure escalation and its duration due to load sharing from
another part of the reservoir which is being drained. The period
for which pressure stays above the initial reservoir pressure is
essentially a time offset for the onset of regular multiphase
effects to be expected in the absence of the Mandel-Cryer effect.
The magnitude of pressure escalation dictates the absolute impact
on hydrocarbon pressure-volume-temperature (PVT) and can also be
used for drainage diagnostics. This allows one to prioritize plays
and sweet spots where this effect could be leveraged to improve
asset NPV.
[0023] One of the goals of the present invention is to understand
the poromechanical mechanisms that lead to delayed CGR changes.
Without understanding the poromechanical physics, reservoir
engineers would be forced to tweak history match models using
non-physical values and are unable to make reliable production
forecasts or design an optimal well operating strategy. Thus, one
of the advantages of the present invention is that it allows
reservoir engineers to design an optimal drawdown strategy which
impacts well and fracture cleanup as well as ultimate resource
recovery.
[0024] Without being limited by theory, it is believed that the
delay in CGR trends observed in producing wells of unconventional
reservoirs can be attributed to the Noordbergum/Mandel-Cryer or
reverse-water-level effects. In soft poro-elastic rocks, pressure
depletion in certain parts of a reservoir can lead to a pressure
escalation in a non-drained region. This can be attributed to
stress transfer and high-low permeability contrast between drained
and undrained parts of a reservoir.
[0025] Based on these principles, simulation-based type curves can
be used to estimate the magnitude and duration of pressure
escalation in the reservoir due to any given applied wellbore
drawdown. Type curves for different mechanical and flow property
configurations are generated using stochastic coupled flow and
geomechanics simulations of the well setup. This can help reservoir
engineers make more reliable estimates of the reservoir pressure
distribution and therefore of the expected fluid pressure,
temperature, and volume (PVT) variations. If the pressure
escalation provided by soft and low perm rock is high enough, the
fluid will continue to stay in a single phase in the reservoir for
an extended duration thereby providing a constant CGR response at
the surface for a longer duration than expected.
[0026] It has been observed that pore pressure can escalate
unexpectedly near certain UR producing wells. This pressure
escalation in turn can lead to an extended period of constant CGR.
This is similar to providing pressure support to producing wells in
conventional reservoirs using mechanisms such as water or gas
injection. However, rather than relying on hydraulic pressure
support (possible in high permeability reservoirs), the pressure
support in low permeability reservoirs should be poromechanic in
nature, due to overburden load sharing.
[0027] FIG. 1 illustrates a pressure escalation that can take place
during fluid drainage in a low permeability, low Young's modulus
environment. The three curves ("A", "B", and "C") correspond to the
pore pressure variations in three different poromechanic property
experimental setups. These curves can be described by the following
relationship:
T = C v t a 2 = E ' k ( 1 - v ) t ( 1 + v ) ( 1 - 2 v ) .gamma. w a
2 ( 1 ) ##EQU00001##
where T is dimensionless time, C.sub.v is coefficient of
consolidation, t is consolidation time, k is coefficient of
permeability, a is drainage distance, E' is Young's modulus of
soil, v is Poisson's ratio, .gamma..sub.w is unit weight of water.
Equation (1) shows that lower Poisson Ratio, lower Young's Modulus,
and lower permeability all lead to higher t (i.e., duration of
pressure escalation).
[0028] FIG. 2 divides the graph in FIG. 1 into a escalation stage
(left) and a depletion stage (right). The pressure escalation is
most pronounced in curve A followed by curve B. Curve C does not
have the obvious local peak of curves A and B. Without being
limited by theory, the pressure escalation is due to lithostatic
load sharing. In other words, as fluid is drained in the producing
well, other parts of the formation are required to take on more of
the overburden load. Certain areas of the formation (e.g., adjacent
and below to the drained reservoir volume) will take on greater
portions of the load corresponding to higher pressure escalation
peaks. This poromechanic effect takes a discernable amount of time
to propagate throughout the reservoir.
[0029] FIG. 3A is a schematic diagram representing the cross
section of an unconventional reservoir with a producer well going
into the plane in the reservoir target directly below the
overburden. As shown, the reservoir includes a high permeability
region (K1) and a lower permeability region (K2). Also shown, is
the producing well (producer) and pressure gauges X, Y, and Z.
[0030] In one embodiment, gauges X, Y, and Z are installed in
separate offset wells. They may also be located in different
sections of a single well or combination of vertical and horizontal
wells or combination of producing (active) and monitoring (passive)
wells. Gauge Z is located closest to the producing well, followed
by gauge X and then gauge Y. After stimulation and production from
the reservoir through the producer well, pressure measurements were
taken in each offset location X,Y, Z. FIG. 3B shows the measured
pore pressure as a function of time. In comparing the three
pressure gauge measurements, readings from gauge Y show the largest
pressure escalation. This is due, at least partly, to gauge Y being
located in a lower permeability region (which prevents pressure
from dissipating quickly) and being subjected comparatively to the
most lithostatic pressure from above.
[0031] Gauge X experiences the second largest pressure escalation.
The pressure escalation in gauge X is lower than the escalation in
gauge Y for a number of reasons. First, gauge X resides in a higher
permeability region as opposed to a low permeability region which
prevents excessive pressure build-up by allowing it to dissipate
more quickly. Since gauge X is installed closer to the surface, it
experiences lower lithostatic pressure as compared to gauge Y.
[0032] Out of the three, gauge Z experiences the smallest pressure
escalation. Gauge Z resides in the stimulated, high effective
permeability region of the reservoir and within a drained reservoir
volume (DRV). As such, the present invention can provide type
curves for quick estimation of pressure escalation at each gauge
location for given mechanical, flow and drawdown conditions.
Moreover, the amplitude and duration of the measured pressure
escalation can be utilized in inverse models to estimate effective
drainage volume and permeability. Since pressure escalation only
takes place in the undrained part of the reservoir, a pressure
escalation in, for example, an offset well (higher than initial
pressure) indicates the depletion extent (DRV) is less than the
distance to offset well. This may be the only way of estimating the
"effective" producing drainage volume (i.e., DRV extent in an
unconventional reservoir). The rate of pressure escalation is
indicative of the rate of hydrocarbon depletion, the DRV effective
permeability, and the DRV effective Young's modulus. A pressure
decrease is indicative of the matrix permeability adjacent to the
monitoring location.
[0033] As described herein, the term "drained reservoir volume"
refers to the portion of the total reservoir that is contacted by
or adjacent to hydraulic fracture stimulation from a well and
therefore experiences hydrocarbon drainage and pressure depletion
with time. Knowledge of the drained reservoir volume helps assess
well stacking-spacing distance and reserves estimation.
[0034] The present invention can assist in designing an optimal
drawdown strategy to maximize well and asset level NPV. One can
design well completion or operating strategies (e.g., choke
setting, number of induced fractures, number of fracture clusters,
choice of stimulation fluid, and/or choice of proppant type) in
order to accelerate hydrocarbon recovery, thereby influencing the
pressure escalation duration and magnitude. Estimation of DRV
dimensions is also extremely important for understanding optimal
well spacing in the reservoir. This can help companies improve
recovery factors.
[0035] Knowledge of when and how much the fluid CGR can change due
to a poromechanical pressure escalation caused by adjacent well's
drainage can assist in improving well productivity forecasts. The
engineer can estimate when to expect a multiphase productivity drop
and can plan for an appropriate artificial lift solution. Whether a
well is within or outside the DRV of another producing well can
also help the engineer estimate appropriate spacing-related
performance degradation and loss of productivity due to well
interference.
Example
[0036] This example describes coupled fluid flow and poromechanic
simulation results that illustrate how various physical parameters
can impact the evolution of pore pressure at a given subsurface
location away from fluid drainage.
[0037] FIG. 4 shows how permeability can impact pressure. Referring
to FIG. 4, one curve (1.5 uD) corresponding to relatively higher
permeability shows a pressure escalation lasting about one year and
then undergoing pressure depletion. The second curve (10 nD)
corresponding to relatively lower permeability shows a more gradual
pressure escalation that can last a decade or so.
[0038] FIG. 5 shows how the Young's modulus can impact pressure.
Referring to FIG. 5, one of the curves (2.8 MM psi) corresponding
to a relatively higher Young's modulus shows a more moderate
pressure escalation and earlier pressure depletion. The second
curve (1 MM) corresponding to a relatively lower Young's modulus
shows a higher pressure escalation but the same rate of pressure
depletion because the permeability remains the same.
[0039] FIG. 6 and FIG. 7 show simulated results of pressure
measurements over time for a reservoir having Km=1.5 uD and YM=2.8
MM psi. As shown, there are 3 curves (FIG. 6) that represent
pressure escalation at three different points (FIG. 7) adjacent to
the producing well. The lateral point or the solid curve
corresponds to a measurement orthogonal to the direction of the
horizontal well. The longitudinal point or dashed curve corresponds
to measurement along the direction of the wellbore but outside its
extent. The final curve in dash-dot corresponds to a far field
pressure measurement in the direction of the horizontal lateral
further away from the well compared to the longitudinal point.
Since it is farther away the pressure escalation signal takes more
time to reach its peak value.
[0040] Although the systems and processes described herein have
been described in detail, it should be understood that various
changes, substitutions, and alterations can be made without
departing from the spirit and scope of the invention as defined by
the following claims. Those skilled in the art may be able to study
the preferred embodiments and identify other ways to practice the
invention that are not exactly as described herein. It is the
intent of the inventors that variations and equivalents of the
invention are within the scope of the claims while the description,
abstract and drawings are not to be used to limit the scope of the
invention. The invention is specifically intended to be as broad as
the claims below and their equivalents.
* * * * *